Emergency control system for subsea blowout preventer

ABSTRACT

An emergency control system (ECS) for a subsea blowout preventer (BOP) includes a frame having a mud mat for engaging a seafloor; an ECS accumulator connected to the frame; a BOP interface connected to the frame and operable to connect to a stack interface of a BOP stack; a valve connected to the frame and operable to supply hydraulic fluid from the ECS accumulator to the interface; an acoustic receiver; and a controller operable to receive an instruction signal from the acoustic receiver and open the valve.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Provisional App. No. 61/411,666 (Atty. Dock. No. WWCl/0017USL), filed Nov. 9, 2010, which is hereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to an emergency control system for a subsea blowout preventer.

2. Description of the Related Art

Bringing an underwater well blowout under control is difficult since it is usually accompanied by hydrocarbons and/or fire at the surface and damage to the subsea equipment connector. This uncontrolled flow of oil and gas is not only a waste of energy but also can be a source of water and beach pollution. Control of the well flow from a blowout and collection of oil spills therefrom have been handled separately. Control of well flow is attempted by drilling separate wells to feed heavy mud into the flowing well to kill the flow.

SUMMARY OF THE INVENTION

Embodiments of the present invention generally relate to an emergency control system for a subsea blowout preventer. In one embodiment, an emergency control system (ECS) for a subsea blowout preventer (BOP) includes a frame having a mud mat for engaging a seafloor; an ECS accumulator connected to the frame; a BOP interface connected to the frame and operable to connect to a stack interface of a BOP stack; a valve connected to the frame and operable to supply hydraulic fluid from the ECS accumulator to the interface; an acoustic receiver; and a controller operable to receive an instruction signal from the acoustic receiver and open the valve.

In another embodiment, a method of safeguarding a subsea drilling operation includes: lowering an emergency control system (ECS) to a seafloor, the ECS comprising: an ECS accumulator, a BOP interface, a hydraulic line extending from the ECS accumulator to the BOP interface, and a valve disposed in the hydraulic line; and operating a remotely operated vehicle (ROV) to connect the BOP interface to a stack interface of a subsea blowout preventer (BOP) stack, wherein the ECS is located at a substantial distance from the BOP stack.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1 illustrates a subsea blowout preventer (BOP) stack, according to one embodiment of the present invention.

FIG. 2 is a flow diagram of an emergency control system (ECS) connected to the BOP stack.

FIG. 3A-3F are operational diagrams illustrating installation and use of the ECS.

DETAILED DESCRIPTION

FIG. 1 illustrates a subsea blowout preventer (BOP) stack 1, according to one embodiment of the present invention. FIG. 2 is a flow diagram of an emergency control system (ECS) 100 connected to the BOP stack 1. The BOP Stack 1 may be employed to control the well during drilling operations in the event of erratic formation pressure causing loss of pressure control, i.e., a kick, which may otherwise lead to a blowout 290 (FIG. 3D). The BOP stack 1 may also be used to secure and disconnect a marine riser 255 (see FIG. 3A) from a wellhead 2 in the event of a mobile offshore drilling unit (MODU) 250 losing position due to automatic station keeping failure, weather, sea state, or mooring failure.

The BOP Stack 1 may be arranged in two sections, including an upper section (aka Lower Marine Riser Package (LMRP)) 5 u which may interface with the riser 255 via a riser adapter 22 located at a top thereof. The LMRP 5 u may further include a flex joint 23 which may accommodate angular movement to compensate for MODU offset. The flex joint 23 may interface with an upper single or dual element hydraulically operated upper annular BOP 12 u for the stripping of drill pipe or tubulars which are run in and out of a wellbore (not shown). The LMRP 5 u may further include a hydraulically operated connector 26 for connection to a mandrel at a top of the BOP stack lower section 5 b.

The BOP stack lower section 5 b may include one or more hydraulically operated ram preventers 10 b,p, such as a blind-shear preventer 10 b and a pipe preventer 10 p, connected together via bolted flanges. Each ram preventer 10 b,p may include two opposed rams disposed within a body. The body may have a bore that is aligned with the wellbore. Opposed cavities may intersect the bore and support the rams as they move radially into and out of the bore. A bonnet may be connected to the body on the outer end of each cavity and may support an actuator that provides the force required to move the rams into and out of the bore. Each actuator may include a hydraulic piston to radially move each ram and a mechanical lock to maintain the position of the ram in case of hydraulic pressure loss. The lock may include a threaded rod, a motor (not shown) for rotationally driving the rod, and a threaded sleeve. Once each ram is hydraulically extended into the bore, the motor may be operated to push the sleeve into engagement with the piston. Each actuator may include single or dual pistons (dual piston shown in FIG. 1, single piston shown in FIG. 2).

Each of the rams may be equipped with seals that engage and prohibit flow through the bore when the rams are closed. The pipe preventer 10 p may include pipe rams operable to engage and seal against an outer surface of drill pipe, thereby closing the annulus. The blind-shear preventer 10 p may include blind-shear rams operable to cut through drill pipe and seal the well. The upper portion of the severed drill string may be freed from the ram while the lower drill string portion may remain in the wellbore. Alternatively, the BOP stack may include a separate blind preventer and a separate shear preventer which may act together to perform the function of the blind-shear preventer. Additionally, the lower section 5 b may include additional pipe preventers (not shown) for engaging and sealing against an outer surface of other tubulars, such as casing (not shown), and/or a redundant drill pipe preventer.

The BOP stack lower section 5 b may further include a lower annular BOP 12 b. The BOP stack lower section 5 b may further include a hydraulically latched wellhead connector 8 connected to a bottom ram preventer via a flange. The wellhead connector 8 may connect to the wellhead 2. The wellhead 2 may lead to the wellbore.

The LMRP 5 u may further include one or more control pods, such as a primary pod 24 p and a backup pod 24 r. Each pod 24 p,r may be in electrical or hydraulic communication with the MODU via a control line 30. Each pod 24 p,r may include one or more control valves 24 a-d and a controller 24 m. Each valve 24 a-d may be in electric or hydraulic communication with the controller 24 m via an electric or hydraulic control line (unnumbered dashed lines). The BOP stack lower section 5 b may further include one or more accumulators 16 for storing pressurized hydraulic fluid. The BOP stack lower section 5 b may further include a frame 28 for supporting the accumulators 16. The accumulators 16 may be in fluid communication with one or more of the control valves 24 a-d for operating the various functions of the BOP stack 1, such as the annular 12 u,b and ram preventers 10 b,p (only blind-shear preventer 10 b shown connected to the pod 24). A hydraulic fluid charge line (not shown) may extend from the accumulators 16 to the MODU 250 for charging the accumulators. Although shown as shutoff valves, the control valves 24 a-d may alternatively be directional control valves, thereby combining functionality of two valves into one valve. The controller 24 m may receive instruction signals form the MODU 250 via the control line 30 and operate the appropriate valves 24 a-d in response to the instruction signals. Each control pod 24 p,r may also include a dead-man's switch (not shown) for closing the preventers 10 b,p,12 u,b in response to a loss of communication with the MODU 250. Each pod 24 p,r may be hydraulically latched to the BOP stack 1 to facilitate maintenance of the pods.

A choke and/or kill line 13 may also extend between the MODU 250 and a port 11 p formed through a body of the pipe preventer 10 p. The choke/kill line 13 line may connect to the stack lower section 5 b at connector 20. A shutoff valve 14 may be disposed at the preventer port 11 p. The shutoff valve 14 may be operated by the pods 24 p,r via an electric or hydraulic control line. Although one line 13 is shown, a separate choke line and a separate kill line may extend between the MODU 250 and respective ports 11 p formed through the pipe preventer body. Alternatively, the choke/kill line 13 may connect to a separate spool (not shown) of the stack lower section 5 b. As discussed above, the LMRP 5 u may further include additional pipe ram preventers (not shown) and each pipe ram preventer may have port(s) to receive the choke/kill line to allow circulation through the BOP Stack column depending on which individual preventer is closed. The choke/kill line 13 may be used to bypass the riser 255 during a well control event, such as a kick. A choke valve (not shown) on the MODU 250 may then be operated to exert backpressure on the annulus while circulating mud through the drill string. Alternatively, the choke/kill line 13 may be used to bullhead the wellbore.

To facilitate connection of the ECS 100, the lower stack section 5 b may further include an interface, such as a junction plate 50. A choke/kill tie-in line 54 may extend from the stack junction plate 50 to the choke/kill line 13 at a lower section of the choke/kill line 13 between the valve 14 and the port 11 p. A shutoff valve 56 may be disposed in the choke/kill tie-in 54. The shutoff valve 56 may have an electric or hydraulic actuator in communication with the stack junction plate 50 so that the valve 56 may be operated from the ECS 100. Alternatively or additionally, the valve 56 may be operated manually by a remotely operated vehicle (ROV) 205 (FIG. 3A) at the stack junction plate 50. An injection line 52 may extend from the stack junction plate 50 to a port 11 b formed through a body of the blind-shear preventer 10 b. A check valve 55 may be disposed in the injection line 52 and operable to allow flow from the junction plate 50 to the preventer port 11 b and prevent reverse flow therethrough. A hydraulic tie-in line 57 (shown in FIG. 2 only) may extend from the stack junction plate 50 to an extension actuation port 15 of the blind-shear actuator. A check valve 58 may be disposed in the injection line 52 and operable to allow flow from the stack junction plate 50 to the actuator port 15 and prevent reverse flow therethrough.

The ECS 100 may include a skid frame 128, a controller 105, a battery 106, a receiver 110, an accumulator 116, one or more interfaces, such as junction plates 150 b,v, an injection line 152, a hydraulic line 157, and a choke/kill line 154. Each of the ECS components may be connected to the skid frame 128 and the skid frame may include retractable legs and a mud mat for supporting and stabilizing the ECS 100 from a floor 201 f of the sea 201 (FIG. 3A). The ECS accumulator 116 may store sufficient fluid energy to extend the blind-shear preventer 10 b one or more times, such as twice. The hydraulic line 157 may provide fluid communication between the accumulator 116 and the BOP junction plate 150 b. A shutoff valve 158 may be disposed in the hydraulic line 157 and have an actuator in hydraulic or electrical communication with the controller 105 via a control line.

A support vessel, such as a light or medium intervention vessel 200 (FIG. 3A), may connect to the vessel junction plate 150 v via a vessel umbilical 151 v. The vessel umbilical 151 v may include one or more fluid conduits and an electrical cable. The junction plate 150 v may connect the electrical cable to the controller 105 for providing electricity from the vessel 200 to the controller and providing data communication between the vessel and the controller. One of the vessel umbilical conduits may connect to the choke/kill line 154 via the vessel junction plate 150 v. The choke/kill line 154 may provide fluid communication between the vessel junction plate 150 v and the BOP junction plate 150 b. A shutoff valve 156 s and choke valve 156 c may be disposed in the hydraulic line 157 and each have an actuator in hydraulic or electrical communication with the controller 105 via a control line. Leads (not shown) may connect the battery 106 and the receiver 110 to the controller 105. The battery 106 may provide electricity to the ECS controller 105 before connection of the vessel umbilical 151 v and the receiver 110 may allow an instruction signal to be sent wirelessly from the vessel 200 before connection of the vessel umbilical 151 v. A second of the vessel umbilical conduits may connect to the injection line 152 via the vessel junction plate 150 v. The injection line 152 may provide fluid communication between the vessel junction plate 150 v and the BOP junction plate 150 b. A check valve 155 may be disposed in the injection line 152 and allow fluid flow from the vessel junction plate 150 v to the BOP junction plate 150 b and prevent reverse flow therethrough.

A BOP umbilical 151 b may connect the junction plates 50,150 b. The BOP umbilical 151 b may have a substantial length D, such as greater than or equal two-hundred fifty, five-hundred, or one-thousand feet, such that the vessel 200 may connect to the ECS 100 while being clear from the BOP stack 1 during the blowout 290. The BOP umbilical 151 b may have a first conduit connected to the hydraulic line 157 via the BOP junction plate 150 b, a second conduit connected to the choke/kill line 154 via the BOP junction plate 150 b, a third conduit in communication with the injection line 152 via the BOP junction plate 150 b, and a control conduit/cable in communication with the controller 105 via the BOP junction plate 150 b. The junction plate 50 may connect the first BOP umbilical conduit to the hydraulic tie-in 57, the second BOP umbilical conduit to the choke/kill tie-in 54, the third BOP umbilical conduit to the injection line 52, and the BOP umbilical control conduit/cable to the actuator of valve 56.

Each of the shutoff valves 56, 156 s, and 158 and choke valve 156 c may be fail-closed and may include an ROV operable override. The choke valve 156 c may also include a visual position indicator for viewing by the ROV 205. Alternatively, each conduit/cable of the umbilicals 151 b,v may be run as separate lines or only some of the lines may be grouped together in an umbilical. Alternatively, the choke valve 156 c may be arranged in a bypass spool of choke/kill line 154 (having shutoff valves straddling the choke valve 156 c) or the ECS 100 may further include separate choke and kill lines (corresponding to separate choke and kill lines of the BOP stack 1).

FIG. 3A-3F are operational diagrams illustrating installation and use of the ECS 100.

The vessel 200 may be deployed during an early stage of a drilling operation, such as after the MODU 250 has cemented the conductor pipe and connected the BOP stack 1 to the wellhead 2. The vessel 200 may include a dynamic positioning system to maintain position of the vessel 200 on the waterline 201 w and a heave compensator to account for vessel heave due to wave action of the sea 201. The vessel 200 may further include a tower 211 having an injector 212 for deployment cable 209. The injector 212 may wind or unwind the deployment cable 209 from drum 213.

The ROV 205 may be deployed into the sea 201 from the vessel 200. The ROV 205 may be an unmanned, self-propelled submarine that includes a video camera, an articulating arm, a thruster, and other instruments for performing a variety of tasks. The ROV 205 may further include a chassis made from a light metal or alloy, such as aluminum, and a float made from a buoyant material, such as syntactic foam, located at a top of the chassis. The ROV 205 may be controlled and supplied with electricity from the vessel 200. The ROV 205 may be connected to the support vessel 200 by a tether 206. The tether 206 may provide electrical, hydraulic, and/or data communication between the ROV 206 and the vessel 200. An operator on the vessel 200 may control the movement and operations of ROV 205. The tether 206 may be wound or unwound from drum 207.

The injector 212 and deployment line 209 may then be used to lower the ECS 100 to the seafloor 201 f through the moonpool of the vessel 200. The ROV 205 may guide landing of the ECS 100. The ROV 205 may then operate the skid frame legs until the mud mat has engaged the seafloor 201 f. Once the ECS 100 has landed on the seafloor 201 f, the ROV 205 may then deploy the umbilical 151 b and connect the umbilical to the junction plates 150 b, 50. The umbilical 151 b may connect to the junction plates 150 b, 50 using hot stabs or hydraulic connectors. Once the umbilical 151 b is connected to the junction plates 150 b, 50, the vessel 200 may leave and drilling operations may continue. The drilling operation may or may not be halted during installation of the ECS 100. Alternatively, the ECS 100 may be deployed by the MODU 250 or any other vessel having an ROV and a hoist.

In the event of the blowout 290 (failure of the BOP stack 1), the vessel 200 may be re-deployed to the ECS site. An acoustic signal 240 may be transmitted from the vessel 200 to the ECS 100 instructing the ECS to open the valve 158. The ECS controller 105 may receive the signal via the receiver 110 and operate the actuator of the valve 158. The accumulator 116 may then inject hydraulic fluid through the hydraulic line 157, junction plate 150 b, the respective conduit of the umbilical 151 b, junction plate 50, hydraulic tie-in 57, and check valve 58 to the blind-shear preventer extension port 15. The fluid path of the hydraulic fluid may bypass the control pods 24 p,r, thereby operating the preventer actuator notwithstanding malfunction of the control pods 24 p,r. Assuming the MODU 250 is burning, the vessel 200 may be deployed and the blind-shear preventer closed before the MODU sinks, thereby reducing the chance sinking debris may obstruct closure of the blind-shear preventer 10 b. If the blind-shear preventer 10 b is successfully closed and damage to the MODU 250 is minimal, then the BOP stack 1 and the MODU 250 may be repaired or replaced and drilling operations may resume or the wellbore may be plugged and abandoned through the BOP stack. If damage to the MODU 250 is extensive (i.e., sunk to the seafloor), then the vessel 200 may remain in place while a relief well is drilled using a new MODU (not shown).

If closure of the blind-shear preventer 10 b fails or is only partially successful, then the ROV 205 may be used to deploy and connect the vessel umbilical 151 v to the vessel junction plate 150 v. Once connected, the vessel 200 may instruct the ECS controller 105 via the electrical cable of the vessel umbilical 151 v to open the choke 156 c and shutoff 156 s valves and the shutoff valve 56. The vessel 200 may then pump heavy mud (aka kill fluid) through the respective conduit of vessel umbilical 151 v, vessel junction plate 150 v, the choke/kill line 154, BOP junction plate 150 b, respective conduit of BOP umbilical 151 b, stack junction plate 50, and choke/kill tie in 54 to the pipe preventer port 11 p in an attempt to bullhead the wellbore. If the bullhead operation fails, then dispersant may be injected through the respective conduit of vessel umbilical 151 v, junction plate 150 v, the injection line 152, junction plate 150 b, respective conduit of BOP umbilical 151 b, and injection line 52 to the blind-shear preventer port while a new MODU drills a relief well.

Alternatively or in response to failure of the bullhead operation, the production fluid from the blowing wellbore may be allowed to flow to production facilities (not shown) located on board the vessel 200 via the choke/kill line 154. If capacity of the production facilities is greater than or equal to the production (blowout) rate of the wellbore, the choke valve 156 c may be controlled to maintain a positive pressure differential in the BOP stack 1 (relative to ambient pressure at the seafloor 201 f), such as greater than or equal to one psig. Production fluid may flow to the vessel through the umbilical and to the production facilities where the production fluid may be separated into crude oil, natural gas, and (produced) water. The crude oil may be stored onboard the vessel or transferred to a tanker or supertanker (not shown). The gas may be flared. The water may be stored for later treatment or treated and pumped into the sea. The BOP stack 1 and/or the ECS 100 may further include a pressure sensor (not shown) in fluid communication with the respective choke/kill line/tie-in 54, 154 and in data communication with the ECS controller 105. As the wellbore is produced, the pressure may be monitored to ensure that the pressure differential is maintained. A hydrates inhibitor, such as methanol, ethylene glycol, or propylene glycol, or dispersant may be injected into the blind-shear preventer port 11 b via the injection lines 52, 152. Alternatively, the ROV 205 may visually monitor the BOP stack 1 for leakage to ensure that the pressure differential is being maintained.

If production capacity is less than the production rate of the wellbore, then the choke 156 c may be kept fully open and the excess production fluid may leak into the sea 201 and, as discussed above, dispersant may be injected into the blind-shear preventer port via the injection lines 52, 152.

Alternatively, the ECS 100 may be operated by the MODU 250, the new MODU, or any other vessel having acoustic transmission capability, an ROV, and/or fluid handling capability. Alternatively, the acoustic signal 240 may be sent by any vehicle having acoustic transmission capability, such as a helicopter dropping an acoustic transmission buoy.

Alternatively, the ECS 100 may not be deployed until after the blowout occurs. The step of sending the acoustic signal may be omitted as the ECS 100 may be lowered with the vessel umbilical 151 v already connected and the ROV may connect the BOP umbilical 151 b or the ROV may connect both umbilicals 151 b,v.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

1. An emergency control system (ECS) for a subsea blowout preventer (BOP), comprising: a frame having a mud mat for engaging a seafloor; an ECS accumulator connected to the frame; a BOP interface connected to the frame and operable to connect to a stack interface of a BOP stack; a valve connected to the frame and operable to supply hydraulic fluid from the ECS accumulator to the stack interface; an acoustic receiver; and a controller operable to receive an instruction signal from the acoustic receiver and open the valve.
 2. The ECS of claim 1, further comprising a vessel interface in communication with the controller and operable to receive an umbilical from a support vessel.
 3. The ECS of claim 2, further comprising a choke/kill line connected to the BOP and vessel interfaces.
 4. The ECS of claim 3, further comprising a choke valve disposed in the choke/kill line.
 5. The ECS of claim 2, further comprising an injection line connected to the BOP and vessel interfaces and having a check valve disposed therein.
 6. The ECS of claim 1, further comprising a battery in communication with the controller.
 7. A blowout preventer (BOP) system, comprising: the ECS of claim 1; a BOP stack, comprising: a shear and/or blind ram preventer; a BOP accumulator; a wellhead connector; a lower marine riser package having a control pod for selectively providing fluid communication between the BOP accumulator and the ram preventer; the stack interface; a hydraulic line extending from the stack interface to an actuator of the ram preventer.
 8. The BOP system of claim 7, wherein the hydraulic line has a length greater than or equal to two hundred and fifty feet.
 9. The ECS of claim 1, wherein the frame is a skid frame and further has retractable legs for engaging the seafloor.
 10. A method of safeguarding a subsea drilling operation, comprising: lowering an emergency control system (ECS) to a seafloor, the ECS comprising: an ECS accumulator, a BOP interface, a hydraulic line extending from the ECS accumulator to the BOP interface, and a valve disposed in the hydraulic line; and operating a remotely operated vehicle (ROV) to connect the BOP interface to a stack interface of a subsea blowout preventer (BOP) stack, wherein the ECS is located at a substantial distance from the BOP stack.
 11. The method of claim 10, wherein: the ECS further comprises an acoustic receiver and a controller, and the method further comprises sending an acoustic instruction signal to the ECS in response to a blowout, wherein the controller opens the valve in response to receiving the instruction signal, thereby providing hydraulic fluid to the stack interface.
 12. The method of claim 11, wherein: the ECS further comprises a vessel interface, and the method further comprises connecting an umbilical from a support vessel to the ECS interface.
 13. The method of claim 12, wherein: the ECS further comprises a choke/kill line connected to the BOP and vessel interfaces, and the method further comprises pumping kill fluid from the vessel to the stack interface via the ECS.
 14. The method of claim 13, wherein: the ECS further comprises a choke valve disposed in the choke/kill line, and the method further comprises flowing production fluid from the stack interface to the vessel via the ECS.
 15. The method of claim 12, wherein: the ECS further comprises an injection line connected to the BOP and vessel interfaces, and the method further comprises pumping dispersant or hydrates inhibitor from the vessel to the stack interface via the ECS. 